1. Field of the Invention
This invention relates to a method and apparatus for creating, producing, enlarging, and depleting artificial natural gas reservoirs in geopressured aquifers in which the waters are at or near methane saturation; or, in which low free gas saturations occur, not producible by conventional gas well completion methods.
2. Description of the Prior Art
Geopressured aquifers are water filled porous rock deposits (surrounded by relatively impervious rock deposits) which exhibit much higher pressure than is normal for water-bearing sands. Geopressured aquifers exist along the Gulf Coast of the United States and in many other places throughout the world where sedimentary deposits have been rapidly buried. Due to the high pressures found in geopressured aquifers, if a well is drilled into the aquifer, water will flow to the surface of the ground in artesian fashion. Natural gas may be present in geopressured aquifers in any of these forms:
(1) Gas dissolved in the water, PA1 (2) Free gas dispersed in water within the rock pores, and PA1 (3) A free gas phase present within the rock pores and separate from the water. PA1 . . published theories of oil and gas migration . . . reveal a rather complete disregard for the basic physical laws which control the movement of gases in a sedimentary column . . . . Methane dissolves in water as individual CH.sub.4 molecules, not as small bubbles of methane. Under the conditions of temperature and pressure existing in the sedimentary column, individual methane molecules do not have an affinity for each other. It is only at the point of liquification (at -160.degree. C.) that methane molecules attract one another. In water, or water-filled sediments, methane is stable, inert, and behaves according to the laws which apply to an ideal gas. It is most important to understand that methane may be present in water in two different states--in solution and in suspension. PA1 In this manner, colloidal-size gas bubbles are readily displaced upward by the surrounding water at rates up to several millimeters per second regardless of any sedimentary particles that may intrude in the way of their upward zig-zag Brownian path. Such exceedingly small bubbles can quickly ascend hundreds or even thousands of feet in a manner not available to larger gas bubbles or to individual gas molecules.
The conventional method of producing hydrocarbon fluids from oil and gas wells is designed to restrict the flow rate so as not to reduce drastically the fluid pressure in the vicinity of the production well which would cause intrusion of water into the well. In order to do this, the well casing is perforated in a zone above the oil-water or gas-water interface. Conventionally, gas well production ceases when water invades the area surrounding the well bore and appreciable quantities of water are produced with the gas.
Publications which relate to the background of this invention and which are referred to herein are as follows.
1. Mac Elvain, "Mechanics of Gaseous Ascension Through a Sedimentary Column," Pp. 15-27, Proceedings of Symposium on Unconventional Methods in Exploration for Petroleum and Natural Gas, Institute for the Study of Earth and Man, Southern Methodist University, Dallas, Texas, 1969.
2. Jones, "Hydrodynamics of Geopressure in the Northern Gulf of Mexico Basin," Jour. Petroleum Technology, v. 21, Pp. 803-810, 1969
3. Stuart, "Geopressures," in supplement to Proceedings of the Second Symposium on Abnormal Subsurface Pressure, Louisiana State University, Baton Rouge, La., 121 p., 1970
4. Hammerlindl, "Predicting Gas Reserves in Abnormally Pressurized Reservoirs," SPE preprint 3479, 6 p., 4 FIGS: Society of Petroleum Engineers of AIME, Dallas, Texas, 1971
5. Perry, "Statistical Study of Geopressured Reservoirs in Southwest Louisiana," SPE preprint 3888, 3 p., 4 tables, 6 FIGS: Society of Petroleum Engineers of AIME, Dallas, Texas 1972
6. Sultanov, et al, "Solubility of Methane in Water at High Temperatures and Pressures," Gazovaia promphlennost, v. 17, no. 5, Pp. 6-7, May 1, 1972
7. Jones, "Natural Gas Resources of the Geopressured Zones in the Northern Gulf of Mexico Basin," Pp. 17-33, Natural Gas from Unconventional Geologic Sources, Board on Mineral Resources, Commission on Natural Resources, National Academy of Sciences, Washington, D.C. 1976
8. Randolph, "Natural Gas from Geopressured Aquifers," SPE preprint 6826, 8 p., 1 table, 8 FIGS: Society of Petroleum Engineers of AIME, Dallas, Texas, 1977
9. Karkalits and Hankins, "Chemical Analysis of Gas Dissolved in Geothermal Waters in a South Louisiana Well" in the Proceedings of the Third Geopressured Geothermal Energy Conference, v. 2, Pp. ED-41-66, University of Southwestern Louisiana, Lafayette, La. 1977
10. Jones, "The Role of Geopressure in the Fluid Hydrocarbon Regime," in Exploration and Economics of the Petroleum Industry, Southwestern Legal Foundation, v. 16, Pp. 211-227, Dallas, Texas, 1978.
11. Jones, "Geopressured-Geothermal Test of the Edna Delcambre No. 1 Well, Tigre Lagoon Field, Vermilion Parish, Louisiana: Geology of the Tigre Lagoon Field," 49 P., 3 tables, 17 FIGS: McNeese State University, Lake Charles, La., 1978
Blowouts, cratered locations, fires, lost holes and lost rigs, stuck pipe, and "impenetrable formations", all associated with abnormally high subsurface fluid pressure, have delayed development of natural gas resources of the geopressure zone. Technology and equipment improvements by the mid-1950's made commercial development possible, and within a few years, thousands of geopressured natural gas reservoirs were in production. By 1960, it was realized that the producing characteristics of geopressured gas reservoirs differed markedly from those of hydropressure zone reservoirs, that the Pz versus cumulative production relationship was not linear, and that unproduced gas reserves could not be estimated by extrapolation of the Pz versus cumulative production curve. The term "Pz" is defined as the corrected gaseous pressure, in which "z" is the gas expansion correction coefficient for natural gas. The ideal value for "z" is 1.0, but for natural gas, which is a mixture comprising mostly methane, with ethane, propane, and butane, the value is frequently less than 1.0, depending upon the gaseous composition.
Data for several thousand geopressured gas reservoirs, now pubicly available, provided the basis for the concept leading to this invention. These records show that, during the early production period (usually the first few years) some pressure-sustaining mechanism causes the rate of reservoir pressure decline per unit of production to be somewhat less than the calculated volumetric rate; during an intermediate period, the rate of pressure decline per unit of production increases; and during a final period, the rate of pressure decline per unit of production corresponds to the conventional volumetric depletion-pressure drop. These changes are disclosed by Hammerlindl (1971). Also disclosed by Hammerlindl (1971) are (a) the calculated reserve based upon the initial slope of the Pz versus cumulative production curve, and (b) the calculated reserve based upon the final slope (volumetric depletion).
It is apparent from Hammerlindl (1971) that, by extrapolation of the calculated reserve from origin (Pz=6,060) at zero production to depletion of the reservoir (Pz=1,500) that some 11 Bcf (billion cubic ft) of natural gas was added to the gas reservoir and its associated bottom water during the productive life of the reservoir. The trend of the Pz versus cumulative production curve shows that most of this gas was added before the Pz value had dropped to 5,000. This is what would be expected to happen, as methane in gas-saturated formation waters associated with a gas reservoir comes out of solution as the pressure declines with production.
The mechanisms by which methane dissolved in water (1) exists in solution, (2) escapes from solution, and (3) migrates upward in colloidal-size bubbles is described in detail by Mac Elvain (1969, p. 15-27), who states that:
In solution, CH.sub.4 exists as separate, completely individual molecules with nearly the same molecular weight as water. The molecular weight of methane is 16. The molecular weight of water is 18. Thus, methane dissolved in water will neither sink nor rise, but will merely move in all directions randomly with all net movement controlled only by the concentration gradient . . . . Methane molecules have absolutely no affinity for each other and . . . a methane gas bubble is not a group of millions of gaseous molecules working together in a common cause, but is merely a property of the cohesive forces of the water surrounding the gas . . . . Supersaturation is actually an environment in which more CH.sub.4 molecules exist than the water can maintain with sufficient distance of separation to preserve them as individual methane molecules. The net result of supersaturation is that two or more methane molecules randomly collide and are forcibly rejected from their intolerable concentration in an elastic film of water surface that creates an exceedingly small gas bubble . . .
Vast numbers of such ultra-small gas bubbles are formed instantaneously when methane-saturated formation water in a sand-bed aquifer is subjected to a drop in fluid pressure. Because of their small size, these tiny gas bubbles are in continuous and random movement, as a consequence of endless collisions with water molecules. Because they contain only a few tens or hundreds of gas molecules, these bubbles are not spherical, and are constantly changing shape. They are instantly knocked loose from nearly everything they touch.
Mac Elvain adds that:
Upward migration of the colloidal size bubbles, resulting from the density contrast between the bubbles and the surrounding water, is enhanced by their continuously changing shape; "kinetic jostling" enables them to worm through the interstices in sediments without becoming stuck to stationary sand or slit particles.
The tiny bubbles accumulate at the top of the sand-bed aquifer, displacing more and more water until critical gas saturation is reached. This gas then flows to, and becomes a part of, the producing gas reservoir--adding to its volume and sustaining its pressure.
The solubility of methane (natural gas) in water is very great at elevated pressures and temperatures. In the geopressure zone of the northern Gulf of Mexico Basin, and in all petroliferous geopressured basins of the world, formation waters are at or near natural gas saturation. The solubility curves disclosed in Sultanov, et al. (1972), show that fresh water at 10,000 psi, for example, can contain in solution 28 standard cubic ft per barrel (scf/bbl) at 220.degree. F.; 41 scf/bbl at 300.degree. F.; 77 scf/bbl at 400.degree. F.; 149 scf/bbl at 500.degree. F.; and 340 scf/bbl at 600.degree. F. Solubilities of methane in the range 2,000 to 16,000 psi and 200.degree. to 625.degree. F. are shown in Table 1.
TABLE 1. ______________________________________ Solubilities of methane in water at selected temperatures and pressures, in standard cubic feet per barrel. (values approximate) Pressure Temperature .degree.F. psi 200 300 400 500 600 656 ______________________________________ 2,000 10 12 20 30 17 3,000 13 17 30 52 80 4,000 15 23 40 76 135 6,000 20 29 52 105 230 380 8,000 24 35 64 130 285 440 10,000 28 41 77 149 340 620 12,000 47 86 168 400 800 14,000 53 95 186 440 900 16,000 58 104 200 480 1,000 ______________________________________
These data and the curves in Sultanov, et al. (1972) support the observation of Perry (1972) that "the larger percentage of economical reserves (found to occur) at the higher pressure gradients reverses the previous concepts that geopressured reservoirs would contain small volumes of reserves." Unit decline of fluid pressure releases far greater amounts of gas (from water solution) at pressures between 4,000 and 12,000 psi and temperatures above 300.degree. F., than at lower pressures and temperatures. At 400.degree. F., volumes released by unit pressure drop are double those at 300.degree. F.; at 500.degree. F., they are quadruple; and at 600.degree. F., they are an order of magnitude greater. Such releases of dissolved methane from high-temperature, high-pressure water associated with abnormally pressured (geopressured) natural gas reservoirs is believed to explain the two distinct slopes evident in plots of shut-in bottom-hole pressures versus cumulative production (Pz plot). Hammerlindl (1971) explains this change of slope, initially gentle and later steep, as the combined effect of changes due to gas expansion, formation compaction, crystal (rock) expansion, and water expansion. No mention is made of the effects of dissolved gas exsolution.
Hydrodynamically induced drop in fluid pressure in a methane-saturated aquifer as a consequence of high flow rates from a well, or wells that tap the aquifer, will cause dissolved methane to come out of solution as dispersed colloidal gas bubbles, in proportion to the numerical relations described in Sultanov, et al. (1972), and listed in Table 1. Continuing discharge from the well(s) causes progressive reduction of fluid pressure in the cone of pressure relief, progressive exsolution of methane, addition of vapor phase methane to the existing bubbles, and progressive expansion of the vapor-phase gas. As the percent of the aquifer pore space occupied by gas exceeds some critical value (50 percent, for example) the water/gas permeability ratio is reversed, and gas flow quickly dominates the fluid regime; water flow essentially stops.
The gas/water permeability ratio critical value will vary for a given aquifer, depending upon such factors as porosity and sand texture. The critical value can, however, usually be determined from test cores from the aquifer in question.
Concurrently with the shift to vapor phase flow, the cone of pressure relief created by the fluid withdrawals spreads very rapidly, because the permeability of reservoir rock to gas is generally an order of magnitude, or more, greater than it is to water. As this occurs, the rate of gas discharge increases markedly, and wells within the boundaries of the newly-created gas reservoir flow methane gas and water vapor. This gas flow continues as long as the expanding cone of pressure relief can cause methane exsolution from aquifer waters. However, after reaching a maximum discharge rate, the flow of gas from the created gas reservoir begins to decline as a result of (1) depletion of the dissolved gas content of aquifer waters within the cone of pressure relief, and (2) increasing distance (radial travel path) from the zone of exsolution to the discharge points (wells). Unless new wells within the area of the created gas reservoir, located at an optimum distance from the initial production wells, can now be opened and produced, the artificial gas reservoir will collapse: the initial production wells will water out, and their produced water will contain only residual amounts of dissolved gas.
Patents considered related to this invention are as follows.
U.S. Pat. Nos. 4,040,487 and 4,042,034 have identical specifications and drawings, and both relate to a process for producing natural gas which is unrecoverable by conventional methods. In applying the method to an appropriate geopressured reservoir, water is produced at a rate sufficient to lower the aquifer pressure and thereby release gas which will migrate and be produced. It is disclosed that it is desirable and necessary to produce water from wells at a very high production rate so as to reduce the formation pressure significantly and preferably as quickly as possible throughout as large an extent of the aquifer as possible. Due to this lowering of the aquifer pressure, gas will be released from solution with the water, will expand and join either the free gas phase dispersed in the water within the sand pores or the free gas present in a gas cap. It may even form a new gas cap if far enough removed from the well so that gravitational forces overcome differential pressure forces which normally cause the gas to flow toward the well. Because natural gas flows more easily through a porous formation than does water, gas will migrate if concentrations greater than residual gas exist. The residual gas concentration will be joined by released gas or expanded gas in the reservoir, and will come to the well bore to be produced with the water which also contains its solution gas. If the producing well is located in a formation close to a free gas phase attic, the lowering of the aquifer pressure can also cause the attic gas to expand and be produced at the well bore as the gas displaces the water and cones into the producing well. Condensate contained in the attic gas would additionally be produced along with the water and gas. A free gas cap remote from the producing well may be created or enlarged and it may be prudent to produce these areas in order to increase gas recovery from the reservoir and thereby to extract the maximum quantity of gas from it.
It is probable that the first targets for producing gas using the method of these prior patents will be the geopressured water sands (aquifers) that underlie and/or overlie producing conventional natural gas reservoirs of the geopressure zone, some 8,000 of which are now in commercial production in coastal and offshore Louisiana and Texas. In the Tigre Lagoon Field, Vermilion Parish, Louisiana, for example, six of eight water sands that occur between depths of 12,000 and 14,000 ft have produced free gas through conventional gas well completions, from wells located in several different parts of the structural high. The two water sands that had not been known to contain free gas were produced through the Edna Delcambre Well No. 1 of Coastal States Gas Producing Company after the well had been temporarily abandoned. Purchased by the United States Energy Research and Development Administration (now Department of Energy) in 1976, the well was recompleted to tap first the No. 3 sand, and later the No. 1 sand, for flow tests and natural gas content. Both sands yielded gas saturated water plus gas that is believed by Randolph (1977) to have occurred in the sand as dispersed bubbles in a low free gas saturation. The geology and hydrology of the field are described by Jones (1978) and the chemistry of produced gas, by Karkalits and Hankins (1977). Results support the assertion of Jones (1976) that all water sands of the geopressure zone in the northern Gulf of Mexico basin are methane saturated.
Contrary to the implications of U.S. Pat. Nos. 4,040,487 and 4,042,034 of Cook, et al., (1977) the most favorable prospects for development of natural gas from geopressured water sands containing low free gas saturations are not in the watered-out parts of produced gas reservoirs, where most of the solution gas originally present in the formation water has been exsolved by pressure drop, and produced to the gas cap.
An ideal candidate aquifer for gas production by this method should have:
(1) A high degree of geopressure and strong water drive.
(2) A moderate resistance to the flow of water and gas--through a range of permeability, for example, of from 20 to 200 millidarcy.
(3) A low free gas saturation, likely where the aquifer is overlain or underlain by conventional gas reservoirs.
(4) Existing gas wells in the vicinity which are still usable for either production or reinjection of water. (5) A shallow salt water aquifer suitable for disposal of produced water.
(6) Attic gas upstructure in the aquifer, perhaps remaining after cessation of production by conventional means.
(7) A high condensate to gas ratio in the attic.
U.S. Pat. No. 2,077,912 discloses the use of a removable packer in a gas well.
U.S. Pat. No. 2,736,381 discloses the use of a packer (24) in an oil or gas well.
U.S. Pat. No. 2,760,578 discloses the use of a packer in an oil well.
U.S. Pat. No. 2,973,811 discloses the drilling of a plurality of wells in a "line drive pattern" in an aquifer containing carbonaceous matter.
U.S. Pat. No. 3,134,438 discloses the use of a packer (34) in an oil well and further discloses fluid coning.
U.S. Pat. No. 3,215,198 discloses the use of a plurality of wells for gas injection pressure maintenance.
U.S. Pat. No. 3,302,581 discloses the use of an inflatable, retrievable packer lifted by gas pressure.
Other United States Patents which do not appear to be as relevant as those above, are: U.S. Pat. No. 1,272,625; 2,230,001; 2,258,615; 3,123,134; 3,177,940; 3,215,199; 3,258,069; 3,330,356, and 3,382,933.